The Effect Of Oil And Gas Molecular Diffusion In Production Of Fractured Reservoir During Gravity Drainage Mechanism By CO2 Injection

Author(s):  
Alireza Kazemi ◽  
Mohammad Jamialahmadi
2020 ◽  
Vol 72 (12) ◽  
pp. 33-33
Author(s):  
Chris Carpenter

The final afternoon of the 2020 ATCE saw a wide-ranging virtual special session that covered an important but often overlooked facet of the unfolding digitalization revolution. While the rising wave of digital technology usually has been associated with production optimization and cost savings, panelists emphasized that it can also positively influence the global perception of the industry and enhance the lives of its employees. Chaired by Weatherford’s Dimitrios Pirovolou and moderated by John Clegg, J.M. Clegg Ltd., the session, “The Impact of Digital Technologies on Upstream Operations To Improve Stakeholder Perception, Business Models, and Work-Life Balance,” highlighted expertise taken from professionals across the industry. Panelists included petroleum engineering professor Linda Battalora and graduate research assistant Kirt McKenna, both from the Colorado School of Mines; former SPE President Darcy Spady of Carbon Connect International; and Dirk McDermott of Altira Group, an industry-centered venture-capital company. Battalora described the complex ways in which digital technology and the goal of sustainability might interact, highlighting recent SPE and other industry initiatives such as the GAIA Sustainability Program and reviewing the United Nations Sustainable Development Goals (SDGs). McKenna, representing the perspective of the Millennial generation, described the importance of “agile development,” in which the industry uses new techniques not only to improve production but also to manage its employees in a way that heightens engagement while reducing greenhouse-gas emissions. Addressing the fact that greater commitment will be required to remove the “tougher two-thirds” of the world’s hydrocarbons that remain unexploited, Spady explained that digital sophistication will allow heightened productivity for professionals without a sacrifice in quality of life. Finally, McDermott stressed the importance of acknowledging that the industry often has not rewarded shareholders adequately, but pointed to growing digital components of oil and gas portfolios as an encouraging sign. After the initial presentations, Clegg moderated a discussion of questions sourced from the virtual audience. While the questions spanned a range of concerns, three central themes included the pursuit of sustainability, with an emphasis on carbon capture; the shape that future work environments might take; and how digital technologies power industry innovation and thus affect public perception. In addressing the first of these, Battalora identified major projects involving society-wide stakeholder involvement in pursuit of a regenerative “circular economy” model, such as Scotland’s Zero Waste Plan, while McKenna cited the positives of CO2-injection approaches, which he said would involve “partnering with the world” to achieve both economic and sustainability goals. While recognizing the importance of the UN SDGs in providing a global template for sustainability, McDermott said that the industry must address the fact that many investors fear rigid guidelines, which to them can represent limitations for growth or worse.


2019 ◽  
Vol 59 (2) ◽  
pp. 762
Author(s):  
Mohammad B. Bagheri ◽  
Matthias Raab

Carbon capture utilisation and storage (CCUS) is a rapidly emerging field in the Australian oil and gas industry to address carbon emissions while securing reliable energy. Although there are similarities with many aspects of the oil and gas industry, subsurface CO2 storage has some unique geology and geophysics, and reservoir engineering considerations, for which we have developed specific workflows. This paper explores the challenges and risks that a reservoir engineer might face during a field-scale CO2 injection project, and how to address them. We first explain some of the main concepts of reservoir engineering in CCUS and their synergy with oil and gas projects, followed by the required inputs for subsurface studies. We will subsequently discuss the importance of uncertainty analysis and how to de-risk a CCUS project from the subsurface point of view. Finally, two different case studies will be presented, showing how the CCUS industry should use reservoir engineering analysis, dynamic modelling and uncertainty analysis results, based on our experience in the Otway Basin. The first case study provides a summary of CO2CRC storage research injection results and how we used the dynamic models to history match the results and understand CO2 plume behaviour in the reservoir. The second case study shows how we used uncertainty analysis to improve confidence on the CO2 plume behaviour and to address regulatory requirements. An innovative workflow was developed for this purpose in CO2CRC to understand the influence of each uncertainty parameter on the objective functions and generate probabilistic results.


SPE Journal ◽  
2019 ◽  
Vol 24 (03) ◽  
pp. 973-987 ◽  
Author(s):  
Neha Anand ◽  
Brandon Tang ◽  
Bradley (Duong) Nguyen ◽  
Chao-yu Sie ◽  
Marco Verlaan ◽  
...  

Summary Application of thermal and solvent enhanced-oil-recovery (EOR) technologies for viscous heavy-oil recovery in naturally fractured reservoirs is generally challenging because of low permeability, unfavorable wettability and mobility, and considerable heat losses. Vapor/oil gravity drainage (VOGD) is a modified solvent-only injection technology, targeted at improving viscous oil recovery in fractured reservoirs. It uses high fluid conductivity in vertical fractures to rapidly establish a large solvent/oil contact area and eliminates the need for massive energy and water inputs, compared with thermal processes, by operating at significantly lower temperatures with no water requirement. An investigation of the effects of solvent-injection rate, temperature, and solvent type [n-butane and dichloromethane (DCM)] on the recovery profile was performed on a single-fracture core model. This work combines the knowledge obtained from experimental investigation and analytical modeling using the Butler correlation (Das and Butler 1999) with validated fluid-property models to understand the relative importance of various recovery mechanisms behind VOGD—namely, molecular diffusion, asphaltene precipitation and deposition, capillarity, and viscosity reduction. Experimental and analytical model studies indicated that molecular diffusion, convective dispersion, viscosity reduction by means of solvent dissolution, and gravity drainage are dominant phenomena in the recovery process. Material-balance analysis indicated limited asphaltene precipitation. High fluid transmissibility in the fracture along with gravity drainage led to early solvent breakthroughs and oil recoveries as high as 75% of original oil in place (OOIP). Injecting butane at a higher rate and operating temperature enhanced the solvent-vapor rate inside the core, leading to the highest ultimate recovery. Increasing the operating temperature alone did not improve ultimate recovery because of decreased solvent solubility in the oil. Although with DCM, lower asphaltene precipitation should maximize the oil-recovery rate, its higher solvent (vapor)/oil interfacial tension (IFT) resulted in lower ultimate recovery than butane. Ideal density and nonideal double-log viscosity-mixing rules along with molecular diffusivity as a power function of oil viscosity were used to obtain an accurate physical description of the fluids for modeling solvent/oil behavior. With critical phenomena such as capillarity and asphaltene precipitation missing, the Butler analytical model underpredicts recovery rates by as much as 70%.


Author(s):  
Hadi Belhaj ◽  
M. S. Zaman ◽  
Terry Lay

Petrel, Eclipse and Monte Carlo are three simulators often used separately to evaluate reservoir structure, production performance and economics/planning/risk analysis respectively. Integration of the three packages provides a very comprehensive and efficient assessment tool for oilfields or blocks with limited data by avoiding incompatibility, data transformation and interface problems. Many oil and gas fields that have been discovered in the past and abandoned as a high risk venture have become of prime interest to numerous smart investors taking advantage of high oil prices and advanced technology. Some of these discoveries have exhibited reasonable hydrocarbon accumulations through seismic surveys, actual drilling and initial well-testing. Their development has previously been hindered by uncertainty and by low oil prices. The ALT Field, North Africa, is a typical example. Only nine vertical wells were drilled in the ALT Field during the 1960’s including three dry holes. Low production from three zones of Chalk Carbonate formation with moderate porosity and very low permeability (less than 1 md), meant the field has been abandoned for over three decades. Recently, with oil prices flourishing, the field has caught the eye of many potential developers. By utilizing the three-simulator approach, the ALT field has been verified as a potential producer of commercial oil. Two scenarios, single-pool and two-pool, have been established for describing the field structure, both are economically feasible, with more profitability foreseen from the single-pool scenario. The two-pool scenario demonstrated the field contains 885MMblls OIIP with estimated total reserves of 310MMbbls of oil using waterflooding alone and an additional 89MMbbls using CO2 injection. The existing six vertical producers are recommended to be used for injection, while a pattern of horizontal wells are suggested to be drilled and used as producers. The horizontal wells are favored over vertical ones to overcome the very low permeability situation. Development of the ALT Field is ongoing based upon the findings of this study. The idea of the three-simulator approach has proven workable, thus has potential to be used in similar cases once minor technical software problems are resolved.


Author(s):  
S. V. Galkin ◽  
◽  
Ia. V. Savitckii ◽  
I. Ju. Kolychev ◽  
A. S. Votinov ◽  
...  

The geological structure of Kashiro-Verey carbonate deposits is considered on the example of one of the deposits of the Perm Region. By combining geophysical studies of wells, standard and tomographic studies of core, the following lithotypes of carbonate rocks were identified: highly porous cavernous, layered heterogeneous porous, heterogeneous fractured porous, dense. It was found that for heterogeneous lithotypes, the porosity estimate in the volume of the permeable part of the rocks significantly exceeds 7%. Experiments on the destruction of rocks were carried out for the selected lithotypes. As a result, it was found that cracks do not form for samples of the cavernous lithotype at a compression pressure of 20 MPa. For a compacted lithotype, already at a compression pressure of more than 10 MPa, an intensive development of fracturing occurs. As a result of multiaxial loading of cores, which can be considered as analogous fracturing of the formation, wide fractures are formed, along which filtration of fluids can occur. Keywords: proppant hydraulic fracturing; X-ray tomography of the core; porosity; permeability; fractured reservoir; oil deposit; carbonate deposits.


Energies ◽  
2019 ◽  
Vol 12 (21) ◽  
pp. 4211
Author(s):  
Timofey Eltsov ◽  
Tadeusz W. Patzek

The non-corrosive, electrically resistive fiberglass casing materials may improve the economics of oil and gas field projects. At moderate temperatures (<120 °C), fiberglass casing is superior to carbon steel casing in applications that involve wet CO2 injection and/or production, such as carbon capture and storage, and CO2-based enhanced oil recovery (EOR) methods. Without a perfect protective cement shell, carbon steel casing in contact with a concentrated formation brine corrodes and the fiberglass casing is superior again. Fiberglass casing enables electromagnetic logging for exploration and reservoir monitoring, but it requires the development of new logging methods. Here we present a technique for the detection of integrity of magnetic cement behind resistive fiberglass casing. We demonstrate that an optimized induction logging tool can detect small changes in the magnetic permeability of cement through a non-conductive casing in a vertical (or horizontal) well. We determine both the integrity and solidification state of the cement-filled annulus behind the casing. Changes in magnetic permeability influence mostly the real part of the vertical component of the magnetic field. The signal amplitude is more sensitive to a change in the magnetic properties of the cement, rather than the signal phase. Our simulations showed that optimum separation between the transmitter and receiver coils ranged from 0.25 to 0.6 m, and the most suitable magnetic field frequencies varied from 0.1 to 10 kHz. A high-frequency induction probe operating at 200 MHz can measure the degree of solidification of cement. The proposed method can detect borehole cracks filled with cement, incomplete lift of cement, casing eccentricity, and other borehole inhomogeneities.


Energies ◽  
2020 ◽  
Vol 13 (23) ◽  
pp. 6215
Author(s):  
Manoj Kumar Valluri ◽  
Jimin Zhou ◽  
Srikanta Mishra ◽  
Kishore Mohanty

Process understanding of CO2 injection into a reservoir is a crucial step for planning a CO2 injection operation. CO2 injection was investigated for Ohio oil reservoirs which have access to abundant CO2 from local coal-fired power plants and industrial facilities. In a first of its kind study in Ohio, lab-scale core characterization and flooding experiments were conducted on two of Ohio’s most prolific oil and gas reservoirs—the Copper Ridge dolomite and Clinton sandstone. Reservoir properties such as porosity, permeability, capillary pressure, and oil–water relative permeability were measured prior to injecting CO2 under and above the minimum miscibility pressure (MMP) of the reservoir. These evaluations generated reservoir rock-fluid data that are essential for building reservoir models in addition to providing insights on injection below and above the MMP. Results suggested that the two Ohio reservoirs responded positively to CO2 injection and recovered additional oil. Copper Ridge reservoir’s incremental recovery ranged between 20% and 50% oil originally in place while that of Clinton sandstone ranged between 33% and 36% oil originally in place. It was also deduced that water-alternating-gas injection schemes can be detrimental to production from tight reservoirs such as the Clinton sandstone.


2006 ◽  
Vol 46 (1) ◽  
pp. 435
Author(s):  
B. Hooper ◽  
B. Koppe ◽  
L. Murray

The Latrobe Valley in Victoria’s Gippsland Basin is the location of one of Australia’s most important energy resources—extremely thick, shallow brown coal seams constituting total useable reserves of more than 50,000 million tonnes. Brown coal has a higher moisture content than black coal and generates more CO2 emissions per unit of useful energy when combusted. Consequently, while the Latrobe Valley’s power stations provide Australia’s lowest- cost bulk electricity, they are also responsible for over 60 million tonnes of CO2 emissions per year—over half of the Victorian total. In an increasingly carbon constrained world the ongoing development of the Latrobe Valley brown coal resource is likely to require a drastic reduction in the CO2 emissions from new coal use projects—and carbon capture and storage (CCS) has the potential to meet such deep cuts. The offshore Gippsland Basin, the site of major producing oil and gas fields, has the essential geological characteristics to provide a high-volume, low-cost site for CCS. The importance of this potential to assist the continuing use of the nation’s lowest-cost energy source prompted the Australian Government to fund the Latrobe Valley CO2 Storage Assessment (LVCSA).The LVCSA proposal was initiated by Monash Energy (formerly APEL, and now a 100% subsidiary of Anglo American)—the proponent of a major brown coal-to-liquids plant in the Latrobe Valley. Monash Energy’s plans for the 60,000 BBL per day plant include CCS to store about 13 million tonnes of CO2 per year. The LVCSA, undertaken for Monash Energy by the Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC), provides a medium to high-level technical and economic characterisation of the volume and cost potential for secure geosequestration of CO2 produced by the use of Latrobe Valley brown coal (Hooper et al, 2005a). The assessment’s scope includes consideration of the interaction between CO2 injection and oil and gas production, and its findings have been publicly released for use by CCS proponents, oil and gas producers and all other interested parties as an executive summary, (Hooper et al, 2005b), a fact sheet (Hooper et al, 2005c) and a presentation (Hooper et al, 2005d)).The LVCSA identifies the key issues and challenges for implementing CCS in the Latrobe Valley and provides a reference framework for the engagement of stakeholders. In effect the LVCSA constitutes a pre-feasibility study for the implementation of geosequestration in support of the continuing development of Victoria’s brown coal resources.The LVCSA findings indicate that the Gippsland Basin has sufficient capacity to safely and securely store large volumes of CO2 and may provide a viable means of substantially reducing greenhouse gas emissions from coal-fired power plants and other projects using brown coal in the Latrobe Valley. The assessment also indicates that CO2 injection could well be designed to avoid any adverse impact on adjacent oil and gas production, so that CO2 injection can begin near fields that have not yet come to the end of their productive lives. However, CCS proposals involving adjacent injection and production will require more detailed risk management strategies and continuing cooperation between prospective injectors and existing producers.


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